Oil & Gas Wells
To produce oil or gas from a reservoir, a well is drilled into a subterranean formation, which may be the reservoir or adjacent to the reservoir. Typically, a wellbore of a well must be drilled hundreds or thousands of feet into the earth to reach a hydrocarbon-bearing formation.
It is desirable to extend the production of wells and to avoid early abandonment when productivity decreases as a result of low natural permeability formation damage.
Well Servicing and Well Fluids
Well services can include various types of treatments that are commonly performed in a wellbore or subterranean formation. For example, stimulation is a type of treatment performed to enhance or restore the productivity of oil or gas from a well. Even small improvements in fluid flow can yield dramatic production results.
Stimulation treatments fall into two main groups: hydraulic fracturing and matrix treatments. Fracturing treatments are performed above the fracture pressure of the subterranean formation to create or extend a highly permeable flow path between the formation and the wellbore. Fracturing treatments are often applied in treatment zones having poor natural permeability. Matrix treatments are performed below the fracture pressure of the formation. Matrix treatments are often applied in treatment zones having good natural permeability to counteract damage in the near-wellbore area.
Hydraulic Fracturing
The purpose of a hydraulic fracturing treatment is to provide an improved flow path for oil or gas to flow from the hydrocarbon-bearing formation to the wellbore. In addition, a fracturing treatment can facilitate the flow of injected treatment fluids from the well into the formation. A treatment fluid adapted for this purpose is sometimes referred to as a fracturing fluid. The fracturing fluid is pumped at a sufficiently high flow rate and pressure into the wellbore and into the subterranean formation to create or enhance one or more fractures in the subterranean formation. Creating a fracture means making a new fracture in the formation. Enhancing a fracture means enlarging a pre-existing fracture in the formation.
A newly-created or newly-extended fracture will tend to close together after the pumping of the fracturing fluid is stopped. To prevent the fracture from closing, a material is usually placed in the fracture to keep the fracture propped open and to provide higher fluid conductivity than the matrix of the formation. A material used for this purpose is referred to as a proppant.
A proppant is in the form of a solid particulate, which can be suspended in the fracturing fluid, carried downhole, and deposited in the fracture to form a proppant pack. The proppant pack props the fracture in an open condition while allowing fluid flow through the permeability of the pack. The proppant pack in the fracture provides a higher-permeability flow path for the oil or gas to reach the wellbore compared to the permeability of the matrix of the surrounding subterranean formation. This higher-permeability flow path increases oil and gas production from the subterranean formation.
A particulate for use as a proppant is usually selected based on the characteristics of size range, crush strength, and solid stability in the types of fluids that are encountered or used in wells. Usually, but not in all applications, a proppant should not melt, dissolve, or otherwise degrade from the solid state under the downhole conditions.
Acidizing
The purpose of acidizing is to dissolve acid-soluble materials. A treatment fluid including an aqueous acid solution is introduced into a subterranean formation to dissolve the acid-soluble materials. In this way, fluids can more easily flow from the formation into the well. In addition, an acid treatment can facilitate the flow of injected treatment fluids from the well into the formation.
Acidizing techniques can be carried out as acid fracturing procedures or matrix acidizing procedures.
In acid fracturing, an acidizing fluid is pumped into a formation at a sufficient pressure to cause fracturing of the formation and to create differential (non-uniform) etching of fracture conductivity. Depending on the rock of the formation, the acidizing fluid can etch the fractures faces, whereby flow channels are formed when the fractures close. The acidizing fluid can also enlarge the pore spaces in the fracture faces and in the formation.
In matrix acidizing, an acidizing fluid is injected from the well into the formation at a rate and pressure below the pressure sufficient to create a fracture in the formation.
Acidizing Sandstone or Carbonate Formations
Acidizing is commonly performed in both sandstone and carbonate formations, however, the different types of formations can require that the particular treatments fluids and associated methods be quite different.
For example, sandstone formations tend to be relatively uniform in composition and matrix permeability. In sandstone, a range of stimulation techniques can be applied with a high degree of confidence to create conductive flow paths, primarily with hydraulic fracturing techniques, as known in the field.
In sandstone formations, acidizing primarily removes or dissolves acid soluble damage in the near wellbore region. Thus, in sandstone formations, acidizing is classically considered a damage removal technique and not a stimulation technique. An exception is with the use of specialized hydrofluoric acid compositions, which can dissolve the siliceous material of sandstone.
Carbonate formations tend to have complex porosity and permeability variations with irregular fluid flow paths. Although many of the treatment methods for sandstone formations can also be applied in carbonate formations, it can be difficult to predict effectiveness for increasing production in carbonate formations.
In carbonate formations, the goal is usually to have the acid dissolve the carbonate rock to form highly-conductive fluid flow channels, which are called wormholes, in the formation rock. In acidizing a carbonate formation, calcium and magnesium carbonates of the rock can be dissolved with acid. A reaction between an acid and the minerals calcite (CaCO3) or dolomite (CaMg(CO3)2) can enhance the fluid flow properties of the rock.
In carbonate reservoirs, hydrochloric acid (HCl) is the most commonly applied stimulation fluid. Organic acids such as formic or acetic acid are used, mainly in retarded-acid systems or in high-temperature applications. Stimulation of carbonate formations usually does not involve hydrofluoric acid, however, which is difficult to handle and commonly only used where necessary, such as in acidizing sandstone formations.
Greater details, methodology, and exceptions regarding acidizing can be found, for example, in “Production Enhancement with Acid Stimulation” 2nd edition by Leonard Kalfayan (PennWell 2008), SPE 129329, SPE 123869, SPE 121464, SPE 121803, SPE 121008, IPTC 10693, 66564-PA, and the references contained therein.
Problems with Acid Fracturing
When the acid is injected above the fracture pressure of the formation being treated, the treatment is called acid fracturing or fracture acidizing. The object is to create a large fracture that serves as an improved flowpath through the rock formation. After such fractures are created, when pumping of the fracture fluid is stopped and the injection pressure drops, the fracture tends to close upon itself and little or no new flow path is left open after the treatment. Commonly, a proppant is added to the fracturing fluid so that, when the fracture closes, proppant remains in the fracture, holds the fracture faces apart, and leaves a flowpath conductive to fluids. In addition to or alternatively to propping, an acid may be used as a component of the fracturing fluid. Depending on the rock of the formation, the acid can differentially etch the faces of the fracture, creating or exaggerating asperities, so that, when the fracture closes, the opposing faces no longer match up. Consequently they leave an open pathway for fluid flow.
A problem with this technique is that as the acid is injected it tends to react with the most reactive rock and/or the rock with which it first comes into contact. Thus, much of the acid is used up near the wellbore and is not available for etching of the fracture faces farther from the wellbore. Furthermore, the acidic fluid follows the paths of least resistance, which are for example either natural fractures in the rock or areas of more permeable or more acid-soluble rock. This process creates typically long branched passageways in the fracture faces leading away from the fracture, usually near the wellbore. These highly conductive micro-channels are called “wormholes” and are very deleterious because subsequently-injected fracturing fluid tends to leak off into the wormholes rather than lengthening the desired fracture. To block the wormholes, techniques called “leak-off control” techniques have been developed. This blockage should be temporary, because the wormholes are preferably open to flow after the fracturing treatment; fluid production through the wormholes adds to total production.
Problems with Matrix Acidizing
When an acidic fluid is used to stimulate a substantially acid-soluble producing, or potentially-producing, formation below the fracturing pressure, the treatment is called matrix stimulation or matrix acidizing. Numerous studies have shown that the dissolution pattern created by the flowing acid occurs by one of three mechanisms (a) compact dissolution, in which most of the acid is spent near the wellbore rock face; (b) wormholing, in which the dissolution advances more rapidly at the tips of a small number of wormholes than at the wellbore walls; and (c) uniform dissolution, in which many pores are enlarged. Compact dissolution occurs when acid spends on the face of the formation. In this case, the live acid penetration is commonly limited to within a few centimeters of the wellbore. Uniform dissolution occurs when the acid reacts under the laws of fluid flow through porous media. In this case, the live acid penetration will be, at most, equal to the volumetric penetration of the injected acid. (Uniform dissolution is also the preferred primary mechanism of conductive channel etching of the fracture faces in acid fracturing, as discussed above.) The objectives of the acidizing process are met most efficiently when near wellbore permeability is enhanced to the greatest depth with the smallest volume of acid. This occurs in regime (b) above, when a wormholing pattern develops.
However, just as wormholing prevents the growth of large fractures, wormholing prevents the uniform treatment of long horizontal or vertical regions of a formation. Once wormholes have formed, at or near a point in the soluble formation where the acid first contacts the formation, subsequently-injected acid will tend to extend the existing wormholes rather than create new wormholes further along the formation. Temporary blockage of the first wormholes is needed so that new wormholes can be formed and the entire section of the formation treated. This is called “diversion,” as the treatment diverts later-injected acid away from the pathway followed by earlier-injected acid. In this case, the blockage must be temporary because all the wormholes are desired to serve as production pathways.
Leak-Off Control or Matrix Diversion
In subterranean treatments in conventional reservoirs, it is often desired to treat a zone of a subterranean formation having sections of varying permeability, varying reservoir pressures, or varying degrees of formation damage, and thus may accept varying amounts of certain treatment fluids. Low reservoir pressure in certain areas of a subterranean formation or a rock matrix or a proppant pack of high permeability may permit that portion to accept larger amounts of certain treatment fluids. It may be difficult to obtain a uniform distribution of the treatment fluid throughout the entire zone. For instance, the treatment fluid may preferentially enter portions of the zone with low fluid flow resistance at the expense of portions of the zone with higher fluid flow resistance. Matrix diversion is different from zonal diversion between different zones.
Similar fluids and methods can be used for “leak-off control” in acid fracturing and for “diversion” in matrix acidizing. Such a method or acidic fluid may be termed a “leak-off control acid system” or “LCA system” or a “self-diverting acid system” or “SDA system” depending upon its use and purpose.
Increasing Viscosity of Fluid for Leak-Off Control or Matrix Diversion
Increasing the viscosity or gelling of a fluid can help divert subsequently introduced fluid from higher permeability to lower permeability portions of a zone. This can be useful for leak-off control in acid fracturing or matrix diversion in matrix acidizing.
A viscosity-increasing agent is sometimes referred to in the art as a viscosifying agent, viscosifier, thickener, gelling agent, or suspending agent. In general, any of these refers to an agent that includes at least the characteristic of increasing the viscosity of a fluid in which it is dispersed or dissolved. There are several kinds of viscosity-increasing agents and related techniques for increasing the viscosity of a fluid.
Polymers for Increasing Viscosity
Certain kinds of polymers can be used to increase the viscosity of a fluid. A purpose of using a polymer can be, for example, to increase the ability of the fluid to suspend and carry a particulate material. Another purpose can be, for example, leak off control or matrix diversion.
Polymers for increasing the viscosity of a fluid are preferably soluble in the continuous phase of a fluid. Polymers for increasing the viscosity of a fluid can be naturally occurring polymers such as polysaccharides, derivatives of naturally occurring polymers, or synthetic polymers.
Treatment fluids used in high volumes are usually water-based. Efficient and inexpensive viscosity-increasing agents for water include certain classes of water-soluble polymers.
As will be appreciated by a person of skill in the art, the dispersability or solubility in water of a certain kind of polymeric material may be dependent on the salinity or pH of the water. Accordingly, the salinity or pH of the water can be modified to facilitate the dispersability or solubility of the water-soluble polymer. In some cases, the water-soluble polymer can be mixed with a surfactant to facilitate its dispersability or solubility in the water or salt solution utilized.
The water-soluble polymer can have an average molecular weight in the range of from about 50,000 to 20,000,000, most preferably from about 100,000 to about 4,000,000.
The viscosity-increasing agent may be provided in any form that is suitable for the particular treatment fluid or application of the present invention. In certain embodiments, the viscosity-increasing agent may be provided in the form of a liquid, gel, suspension, or solid that is mixed or incorporated into a treatment fluid used in conjunction with the present invention.
Crosslinking of Polymer to Further Increase Viscosity of a Fluid or Form a Gel
The viscosity of a fluid with a polymeric viscosity-increasing agent can be greatly increased by crosslinking the viscosity-increasing agent. A crosslinking agent, sometimes referred to as a crosslinker, can be used for this purpose. A crosslinker interacts with at least two polymer molecules to form a “crosslink” between them.
The degree of crosslinking depends on the type of viscosity-increasing polymer used, the type of crosslinker, concentrations, temperature of the fluid, etc. Shear is usually required to mix a base gel and the crosslinking agent. Thus, the actual number of crosslinks that are possible and that actually form also depends on the shear level of the system.
If the polymeric viscosity-increasing agent is in a sufficient concentration and crosslinked to a sufficient extent, the polymer may form a gel with water. Gel formation is based on a number of factors including the particular polymer and concentration thereof, the particular crosslinker and concentration thereof, the degree of crosslinking, temperature, and a variety of other factors known to those of ordinary skill in the art.
Breaking Fluid Viscosity or Gel
After a treatment fluid is placed where desired in the well and for the desired time, the viscous fluid or gel usually must be removed from the wellbore or the formation to allow for the production of oil or gas. To accomplish this removal, the viscosity of the treatment fluid must be reduced to a very low viscosity, preferably near the viscosity of water, for optimal removal from the zone of the subterranean formation.
Reducing the viscosity of a viscosified fluid is referred to as “breaking” the fluid. Chemicals used to reduce the viscosity of fracturing fluids are called “breakers.”
No particular mechanism is necessarily implied by the term. A breaker or breaking mechanism should be selected based on its performance in the temperature, pH, time, and desired viscosity profile for each specific treatment.
Iron-Based Crosslinking Systems
An example of such a leak-off control acid system or self-diverting acid system is described in European Patent Application Publication No. 0278540 B1, assigned to Schlumberger Technology. The strongly acidic system initially has low viscosity but includes a soluble ferric ion source and a polymeric gelling agent that is crosslinked by ferric ions at a pH of about 2 or greater but not at a lower pH. However, the polymer is not crosslinked by ferrous ions. Therefore, the system includes a reducing agent that reduces ferric ions to ferrous ions, but only at a pH above about 3 to 3.5. Consequently, as the acid spends, for example in a wormhole, and the pH increases to about 2 or greater, the polymer crosslinks, and a very viscous gel forms that inhibits further flow of fresh acid into the wormhole. As the acid spends further and the pH continues to rise, the reducing agent converts the ferric ions to ferrous ions and the gel reverts to a more fluid water-like state. Hydrazine salts and hydroxylamine salts are specified as the reducing agents.
Another example is described in U.S. Patent Publication No. US 2005/0065041 A1, assigned to Schlumberger Technology. Reducing agents or reducing agent precursors are provided for breaking ferric ion crosslinks in polymers in gelled acids used for diversion in matrix acidizing and used for leak-off control in acid fracturing. Previous reducing agents were very toxic to aquatic species or so active that they could be used only at low temperatures. The described reducing agents and reducing agent precursors for iron are less reactive, less toxic, and leave less residue behind to impede fluid flow after the gel is broken after the treatment. Suitable compounds are disclosed as being sources of one or two hydrazines or sources of hydroxylamine. Such compounds are carbohydrazides, semicarbohydrazides, ketoximes, and aldoximes.
Iron-based crosslinkers such as ferric chloride for in-situ crosslinking in acidizing systems have a tendency to form iron depositions, precipitation, sludge, and scale formation during the acidizing treatment when the acid is spent, which damages the subterranean formation.
There is a continuing need for an alternative to iron-based crosslinking systems for acidizing using fluids that become highly viscous or gelled in a desirable pH range and then breaking for flow back from the subterranean formation. Therefore, an objective of this project was to develop an alternative crosslinker for the ferric chloride, while maintaining overall treatment performance of the in-situ crosslinking for an acidizing system.
In addition, there is a continuing need for acidizing fluids that can be used with concentrated acids, especially, for example, greater than 20% hydrochloric acid or other acid compositions having a pH less than zero.